Hydrocarbon producing wells include wellbores that are typically drilled at selected locations into subsurface formations in order to produce hydrocarbons. A drilling fluid, which can also be referred to as “mud,” is used during drilling of the wellbores. Drilling fluid is used in the drilling of a wellbore and it serves a number of purposes, such as cooling of the drill bit, carrying cuttings to the surface, provide pressure to maintain wellbore stability and prevent blowouts and the sealing off of the wellbore. The wellbore should be sealed to minimize the loss of drilling fluids into the formation. For safety purposes, a majority of the wellbores are drilling under over-burdened or overpressure conditions, i.e., the pressure gradient in the wellbore due to the weight of the mud column is greater than the natural pressure gradient of the formation in which the wellbore is drilled. Because of the overpressure condition, the mud penetrates into the formation surrounding the wellbore to varying depths, thereby contaminating the neutral fluid contained in the formation.
To minimize the loss of drilling fluids into the formation, components in the drilling fluid, such as clays, fillers and lost circulation materials, are used to restrict flow of the drilling fluids into the formation and to form a filter cake at the wellbore wall. The filter cake can provide a seal for the wellbore into the formation. Drilling fluids that have entered the formation to some extent have displaced the formation fluids, which can be referred to as drilling fluid filtrate.
The drilling fluids, or muds, used for drilling the wellbores can be water based or organic based. Organic based drilling fluids can be further distinguished as being natural based or synthetic based. For instance, organic based drilling fluids can include natural and/or synthetic hydrocarbons. A natural organic based drilling fluid is one where the primary component is a natural component that can include hydrocarbons, similar in nature to those usually produced from fields. Additionally with recirculation or reuse the drilling fluids can obtain components from the area. Natural organic based drilling fluids can include synthetic components that are added to impart certain properties. A natural organic based drilling fluid is one where the primary component is a natural organic material. A synthetic based drilling fluid is one where the primary component is a synthetic material. Both natural and synthetic based drilling fluids can therefore contain one or more synthetic material(s) that is distinct from the formation fluid that is naturally occurring in the formation. As well synthetic fluids can contain natural components that appear similar to the properties of formation fluid. A commonly used drilling fluid is oil based mud (OBM). OBM in the context herein should be understood to include synthetic-based oleic muds or natural based oleic muds, where synthetic, non-aqueous liquids are part of the base fluid.
Once a well is drilled it is desirable to obtain formation fluids from zones of interest to analyze and obtain properties thereof. If there is a drilling fluid filtrate that has contaminated the near wellbore area of the formation, this will alter the analysis of the samples being analyzed and will not be representative of the actual formation fluid. During a formation pumpout the first drawn fluid will be predominately drilling fluid filtrate. To minimize this contamination, fluids drawn from the formation are taken from an isolated area of the wellbore over time, which can be referred to as a pumpout. As the pumpout proceeds the degree of contamination in the samples should decrease over time and each subsequent sample should increase in formation fluid content and decrease in contamination content until a steady state is achieved.
Analysis, techniques and methods are known in the art that rely on monitoring changes in properties, such as density or resistivity and current optical methods, throughout the pumpout, curve fitting the results, such as through error function or arc tangent calculations, and obtaining steady state approximations with the assumption that when steady state is reached there is no contamination.
To estimate or determine the type of the fluid, including oil and/or gas and/or water and the characteristics of the fluid, in a formation at a particular wellbore depth and to estimate the condition of the reservoir surrounding the wellbore at the particular depth, downhole tools are used during drilling of the wellbore and after the wellbore has been drilled to obtain samples of the downhole fluid, also referred to as the formation fluid. The downhole tools for use in methods for analyzing downhole fluids can be conveyed into a wellbore via wireline tubing or coiled tubing, or any other suitable means. Methods of measuring using wireline conveyed tools, include lowering a wireline tool including an analyzer into a wellbore at a desired depth. These wireline tools may contain optical imaging tools for detecting the contents of downhole fluids. Other methods for analyzing downhole fluids include the method of logging while drilling (LWD) or measurement while drilling (MWD). LWD/MWD are techniques of conveying well logging tools and/or measurement tools, including downhole tools, into the wellbore hole as part of a bottomhole assembly. During drilling of the wellbore, these downhole tools are disposed in a bottomhole assembly above the drill bit. In some methods, LWD/MWD tools contain optical imaging tools for detecting the contents of downhole fluids.
To obtain a sample of formation fluid, a probe is often used to withdraw fluid from a formation. However, the formation fluid up to a certain depth adjacent to the wellbore can be contaminated with the mud or in other words contains mud filtrate. To obtain a clean sample of the formation fluid, the formation fluid is withdrawn for a certain period of time before taking the sample. Typically as drilling fluid is recycled in a well, the drilling fluid picks up characteristics of the well. Often times the drilling fluid is recycled within a field, and picks up characteristics of the field. Typically drilling fluid will contain between 10% to 90% of natural material from the field. However, the drilling fluid will often maintain some of the same characteristic of the base oil, making the amount of contamination of the formation fluid difficult to observe. Inaccurate readings of formation fluid samples can cause costly delays and expensive production shutdowns.
Current methods of formation fluid analysis of filtrate contamination during sampling rely on curve fitting of fluid analysis results until a near steady state composition is obtained, but a steady state composition can be obtained while still having significant or even majority contamination present.
Therefore, there is a need to give a real or near-real time determination of filtrate contamination in formation fluid sample. There is also a need to improve accuracy on determination of when filtrate contamination is at an acceptable level and to decrease the time involved in making such a determination.